Adaptive Method for High Data Rate Communication In Wells

ABSTRACT

Apparatus for downhole transmission and reception of data in an oil or gas well includes a downhole signal transceiver adapted to receive data from a signal generator and transmit the signal through the well and an elongate member with an axis, located in the wellbore; wherein the signal is transmitted by the transceiver, predominantly axially along the elongate member.

TECHNICAL FIELD

This invention relates to an apparatus and method for downhole transmission of signals.

It is normally desirable to measure various parameters during drilling and subsequent testing of an oil or gas well, for example pressure, temperature, formation data, and wellbore trajectory at or near the bottom hole assembly (BHA) and drill bit and along the well bore, and to relay these measurements back to the surface where the drilling operation can be controlled. During drilling operations, the weight on bit and rate of rotation of the drill string are two typical parameters that are controlled at the surface in order to affect the rate of penetration of the drill bit through the formation. For example, it is desirable for the drilling engineer controlling the drilling operation at the surface to know when the drill bit is experiencing aggressive local conditions as it cuts into the formation, such as high temperatures, pressures, or resistance to penetration, so that they can adjust for example the rate of rotation, the weight on bit, and the rate of supply of drilling fluid to the bit in order to avoid driving the bit beyond it's normal operational parameters and thereby reducing the risk of bit failure, which would require expensive and time consuming intervention. This Measurement While Drilling (MWD) is well known in the art and various mechanisms have evolved for gathering data at the bit and transmitting these data back to the driller at the surface. The present invention relates particularly to novel aspects of the transmission of signals or data (such as Measurement While Drilling, Logging While Drilling, Seismic While Drilling, and Formation Evaluation While Drilling) gathered at the bit or at points along the drill pipe or well-bore and transmitted to the surface, and also to the transmission of signals from the surface down the well towards the bit in order to control or operate any downhole tools or devices.

According to the present invention there is provided apparatus for downhole transmission and reception of data as claimed in the accompanying claims.

Also according to the present invention there is provided a method of downhole transmission of data as claimed in the accompanying claims.

Also according to the present invention there is provided apparatus comprising a wireless network formed by the interaction of transceiver nodes as claimed in the accompanying claims.

Also according to the present invention there is provided apparatus comprising high data rate electrical signal pathways as claimed in the accompanying claims.

Also according to the invention there is provided apparatus for downhole transmission and reception of data in an oil or gas well, the apparatus comprising a downhole signal transceiver adapted to receive data from a signal generator and transmit the signal through the well; and an elongate member with an axis, located in the wellbore; wherein the signal is transmitted by the transceiver, predominantly axially along the elongate member. The invention also provides a method of downhole transmission and reception of data in an oil or gas well, the method comprising providing a downhole signal transceiver adapted to receive data from (a) signal generator and transmit the signal through the well; providing an elongate member with an axis, extending through the wellbore; and transmitting the signal from the transceiver along the elongate member.

Optionally more than one downhole transceiver is provided, e.g. 2, 3, 4, or more transceivers are linked optionally in series as nodes along the elongate members Optionally the signals transmitted comprise signals from the or each transceiver, and one or more sensors in the well. Typically the signal presented at the transceiver nodes and at the elongate members is a radio frequency (RF) signal and the elongate member incorporates a conductor comprising a conductive element or material which can act as an effective carrier or transmitter of RF signals. Typically the signal conductor can comprise a metal and can optionally comprise a metallic strip or component optimised in its electrical or material properties or dimensions to carry the RF signal. Typically the signal is transmitted along the length of the elongate member. The conductor can optionally be optimised in its effectiveness of carrying or transmitting RF signals by variations to its electrical impedance, through changes to its material composition or morphology and/or changes to its physical arrangements such as width, thickness, length and separation from adjacent surfaces, which can influence its electrical impedance and electrical resistance and efficiency at carrying RF signals. Optionally, the electrical conductor will be electrically insulated from the environment by resting within electrically-insulating materials optimised for the RF signals being transmitted. Optionally, the electrical insulating materials can be coated with further protective layers which may be electrically conducting.

Typically the signal can be transmitted wirelessly across the connections between elongate members, and optionally across members themselves, by which is meant that the signal can be transmitted across regions of space and distances in which no traditional wires or traditional electrical conductors are in intimate contact with each other.

Typically the elongate member comprises a downhole tubular, typically with a hollow bore through the tubular. Typically the downhole elongate member is adapted to connect into a string of elongate members. Typically the string is a string of tubulars configured to provide a fluid pathway through the bore of the string. The tubular can optionally be formed and arranged in separate lengths or sections which are connected together as the string is being made up, as is known in the art. For this purpose, the tubular can optionally have end connections adapted to interconnect to form the string. Box and pin arrangements that are well known in the art are suitable for this purpose, although other connection types are within the scope of the invention.

Typically end connectors adapted to interconnect adjacent stands of tubular can have radial lips or other projections extending radially outward from the nominal outer diameter of the tubular as is known in the art.

Typically the apparatus comprises a series of signal conductors adapted to provide a signal pathway for passage of the signal transmitted from the transceiver nodes through the well. The signal conductors are typically mounted on the surface of the elongate members.

Typically the signal conductor has a lower electrical transmission loss to transmission of the signal than the elongate member or the surrounding fluid medium, thereby increasing the efficiency of transmission between transceivers. Typically the signal conductor comprises a network of strips of electrically conductive material provided in a layer Typically the layer can extend substantially circumferentially around the outer or inner surface of the tubular, although in certain embodiments, the signal conductor can be incorporated within the wall of the tubular instead of being subsequently applied to it. Typically the signal conductor can extend axially along the elongate member, as well as circumferentially, so that the signal carried by the signal conductor is transmitted along the conductor and along the axial length of the elongate member. Typically the signal conductor is formed substantially circumferentially around the elongate member. For example, the signal conductor can optionally cover a substantial portion of the circumference of the elongate member. Alternatively, the signal conductor can cover a small or large part of the circumference of the elongate member, e.g. any proportion of the circumferential distance around the elongate member.

Optionally the signal conductor can extend between the two ends of an elongate member, and in some embodiments of the invention, the signal conductor can optionally terminate before the end of the section of tubular, and does not necessarily require a continuous electrical connection to be made between the signal conductor on one section of elongate member, and the signal conductor on the adjacent sections. In certain embodiments the signal conductor can comprise one or more axially-aligned strips. Typically more than one axial strip is provided and adjacent axially-aligned strips can optionally be parallel to one another, so that they extend parallel to the axis along the length of the elongate member. In some embodiments, it may be desirable to have non-parallel alignments of the strips, to provide for example, useful geometries to avoid certain damage mechanisms at certain positions along the elongate member. In certain embodiments, the signal conductor can be of uniform dimensions of width and thickness along the length of the signal conductor. In certain embodiments, the width and thickness of the signal conductor may vary along its length or at its ends as required by optimum transmission and reception of the signals. In certain embodiments, the physical dimensions (width and thickness) of the insulating layers can be uniform along the length of the elongate member. In certain embodiments the physical dimensions of the insulating layers along the length of the elongate member may vary, as required by optimum transmission and reception of the signals.

The signal conductor can optionally form a mesh of wires or strands of metal. The wires or strands in the mesh can optionally have physical interconnections between different strands of wire, and these can be regular or irregular. Optionally, wires or strands in the mesh can instead or additionally be pressed into contact with adjacent wires, without structural connections between them. In either event, the mesh typically comprises numerous electrical interconnections between adjacent strands of metal in the signal conductor (which can be formed from physical connections resisting disconnection of the wires, or from simple contact between adjacent wires that are touching, without any other kind of physical inter-connection) so that the signal pathway along the axial length of the tubular through the conductor has many different optional routes to travel typically in a predominantly axial direction, through the conductor. The signal conductor can optionally be a mesh such as a sheet or layer of woven material that is optionally planar, and optionally of a generally uniform thickness, which can typically be wrapped around the outer surface of the tubular. The mesh can be regular or irregular in pattern and strands of individual wire making up the mesh can be continuous or non-continuous. The mesh can be wrapped around or adhered to the outer surface of the tubular in a flat sheet or can be formed in a sleeve with a bore which is passed over the tubular and therefore fixed to its exposed surface.

In typical embodiments of the invention, the signal conductor comprises an electrically conductive metal Optionally the tubular member and conductor are formed from different metals and the conductor is typically inherently adapted to transmit the signal with a lower signal loss and with a higher data transmission rate than the tubular. Preferred metals for the conductor are those that are electrically conductive and include various states and qualities of copper, or for example, zinc, aluminium, iron, steel, gold, platinum and silver and their alloys. Typically, the tubular has a coating that spaces (e.g. radially spaces) the signal conductor from the material of the tubular.

Typically the coating is an electrically isolating coating that electrically isolates the signal conductor from the elongate member. Optionally the signal conductor can be covered by the coating, so that the signal conductor is optionally embedded within the layer of coating and located between the surface of the coating and the inner bore of the tubular. The signal conductor can be formed integrally with the coating or in a separate process. The signal conductor can be moulded, sprayed or cast or otherwise applied (by various different methods known to the skilled person) inside the electrically-isolating coating, and the coating and the signal conductor can optionally be applied around the full circumference as an integral wrap (or in separate wraps) around the outer or inner exposed surface of the tubular.

Typically, the coating material has high resistivity to minimise the unwanted flow of electrical charge and has properties beneficial to the transmission of electrical signals and RF signals such as dielectric loss and dielectric constant optimised for the geometry and the RF signals.

Typically the coating comprises an insulating material (e.g. an electrical insulator) and typically the coating isolates the signal conductor from the tubular and from the local environment. Ceramic materials such as Alumina, Yttria-Stabilised Zirconia, Zirconia, Silica, combinations therefor similar materials are useful in this regard for application to oil well drill pipe, production pipe or casing pipe, due to the temperature-resistant and wear resistant properties. For other less demanding applications, less hardy electrical insulators such as plastics, polymers, epoxies, paints and lacquers may be considered.

The tubular (elongate member?) can optionally have additional, one or more, abrasion resistant materials on its exposed (e.g. outer) surface adapted to protect the signal conductor and other insulating coatings against abrasive damage, impacts, wear and erosion etc. The additional abrasion resistant material can optionally comprise the protective coating, and/or can be applied separately to the exposed (e.g. outer) surface of the existing conductor or coating. The additional abrasion resistant material typically comprises a hard material such as alumina or tungsten carbide, or a similar material that resists impact, wear and erosion on the exposed surface. The outermost abrasion resistant material is typically provided on the exposed surfaces of the tubular likely to receive greatest wear or impact. Optionally, this abrasion resistant material can also have electrical properties that will enhance the transmission of electrical signals and RF signals, rendering the outer-most abrasion-resistant material to be optionally electrically resistive or electrically conducting, as dictated by the electrical losses that are allowable for a specific application or part of the elongate member.

Embodiments of the invention therefore typically provide a series of successive signal conductors on each adjacent section of tubular which provide a low loss path for the transmission of the signals from the sensor at one end of the string of tubulars and along the string to the signal collection point at the other. In for example drilling operations, the sensor can typically be at the bottom end of the well adjacent to the bit, and the signal collection point can typically be at the surface, so that the signal travels up the string from the bit to the surface. However, in some embodiments, the signal can travel from the surface to a device or other signal collection point at intermediate locations in the well, for example in the down hole tool located in the string, for example at the bottom hole assembly.

Optionally the signal conductor extends axially from one point adjacent to one end of the tubular towards the other end. Optionally each section of tubular between end connections has one or more respective transceiver nodes adapted to receive a signal from an adjacent section of tubular and retransmit the signal along the next section of tubular. In some embodiments it is not necessary for each section of tubular or each section of signal conductor to have a corresponding separate transceiver node on each section, and transceiver nodes can be provided on the string at locations separated spatially in accordance with the desired strength of the signal and transmission rates of the signal.

Typically each transceiver node transmits the signal wirelessly, typically as radio frequency signals, without requiring a direct electrical connection to the signal conductor. The transceiver nodes are typically located close to or applied radially over the signal conductor (but typically electrically insulated there from by the coating or the abrasion resistant layer) so that the RF signal transmitted by the transceiver node is picked up wirelessly by the signal conductor and transmitted along the signal pathway provided by the signal conductor from one end of the section of tubular to the other. At the other end of the tubular, the transceiver node on the next section of tubular (or the signal conductor on the next section of tubular) picks up the transmitted signal from the end of the adjacent tubular section and transmits it along the signal conductor located on the next tubular section. In this way, each section of tubular receives and optionally boosts the signal and sends it axially along the length of the string.

Typically the transceiver nodes comprise collars or annular housings that are applied to the outer surface of the tubular, typically over the outer surface of the signal conductor. Alternatively, the transceiver node can be incorporated as a sub assembly terminating in similar connections to the elongate members and inserted between two such members if desired. In certain embodiments, the transceiver can be incorporated within the wall of the tubular, as typified in a side-pocket mandrel, but it is often useful to be able to retrofit existing sections of tubular with embodiments of the invention, so externally-applied and wrap-around transceiver nodes are considered to be the most useful embodiments within the scope of the invention. Typically, the transceiver nodes can comprise attachment devices to connect physically to the tubular, such as clamps, straps, friction reducers, annular spacers etc., arranged optionally, as annular ‘split-rings’ that can be connected to the elongate members prior to their insertion into a well, for example, at the rig floor.

Typically the transceiver node can incorporate one or more of a power supply, for example a battery, voltage regulation, any number of radio frequency transmitters operating at various frequencies, any number of radio frequency receivers operating at various frequencies, associated amplifiers, modulators, microprocessors, signal conditioning and processor devices and optionally one or more sensors adapted to report vibration, temperature, pressure, and other conditions in the well. Embodiments of the invention provide two-way high data rate communication systems. The combination of transceiver nodes plus the network of electrical interconnections in the signal conductor typically forms an adaptive network, and the signal being transmitted along the system finds the path of least electrical loss to the transmission and this leads to more reliable, effective and faster data transmission, and minimises energy consumption during the transmission process. Optionally, as the conductor does not require full electrical continuity along its length between the transceiver nodes, damage to any particular section of coating or conductor or the loss of an individual transceiver node does not result in loss of the data, or loss of ability to transmit along the signal path within the energy capacity of the system. The electrical conductor geometries and network of interconnections also provides for redundancy in the pathway of the conductor in the event of component failures at any point of the elongate member.

Embodiments of the invention can typically achieve higher data transmission rates than was previously possible as a result. Typical excitation frequencies are up to Giga Hertz enabling data transmission rates from bits per second through to Megabits per second or more. Each data set transmitted in the signal is typically identified by a unique marker (typically encoded in the RF signal) so that the source and significance of each data reading can be differentiated at surface. This tagging of data sets is typically applied to each of the multiple data types generating from the BHA and from each sensor in the various transceiver nodes taking readings along the well bore path to the surface. Additionally the transceiver nodes themselves typically each have a unique marker (typically encoded in the RF signal) to distinguish each node from any

other node, and allow identification of each node from the surface. Corruption of the data transmitted along the elongate members can optionally be detected using techniques well known in the art such as parity checks. To minimise the need for retransmission of data when only partial corruption of the data has occurred, techniques well known in the art such as Forward Error Correction may be optionally implemented.

To minimise the effect of commonly occurring radio frequency communication problems such as interference or multipath cancellation, techniques well known in the art such as spread spectrum, error correction and encoding techniques such as Manchester encoding may optionally be implemented in the embodiment.

The transceiver nodes may be managed by a proactive link-state routing protocol, which uses beaconing, and topology control (TC) messages to discover and then disseminate link state information throughout the ‘ad-hoc’ network. Individual transceiver nodes use this topology information to compute next hop destinations for all nodes in the network using the most energy-effective hop forwarding paths. Optionally, as each packet of data is received at a transceiver node, it will, as described above, typically confirm receipt back to the originating transceiver node via ‘hand shake’ protocols that are known in the art. If a transmitting node fails to receive a confirmation ‘hand shake’ from the node to which it was previously transmitting, it can optionally be programmed to change the transmitted signal (by amplitude or frequency) to transmit over greater distance or, in the event of node failure, to by-pass the silent node and reach the next node in sequence and then maintain as default this new communication pathway and signal transmission characteristics. In this manner, damaged transceiver nodes, or damaged electrical conducting elements, can be by-passed or accommodated without substantial loss of data transmission integrity and the damaged or ineffective elements in the signal communication system can be adequately compensated for, as the optimised RF transmission frequencies and amplitudes are identified by these automated processes.

Alternatively, the transceiver nodes can optionally be programmed to achieve the same purpose by reducing the bandwidth or frequency of the data transmissions to reduce noise levels, attenuation and hence power requirements to cover the extended transmission distances that may be necessary to traverse as a result of component failures. Failure to receive confirmation of data receipt from a transceiver node can optionally also trigger the generation and transmission of a node failure report to the data stream to identify at surface that the node is not functioning, and optionally to identify the location of the failed node. This method and process described above is known in the art as ‘adaptive mesh networking’, and alternatively as ‘ad-hoc networking’.

In one embodiment the transceiver nodes operate using an unmodified commercial mesh networking protocol to manage the adaptive network routing between nodes. Optionally, the system can use a protocol specifically adapted to optimise efficiency in a network where the nodes are linearly distributed or axially aligned.

When, as in for example for drill pipes in well, the elongate members (drill string tubulars) are recovered to surface the identified failed nodes can then optionally be repaired, or removed and replaced.

Optionally the transceiver nodes can incorporate coding devices adapted to incorporate such sensor data gathered from the local transceiver into the signal transmitted by the local transceiver through the signal conductor. Optionally each transceiver node has a code that uniquely identifies that transceiver node. Optionally the signal transmitted and received by each transceiver node in the assembled string can be the same, but in some embodiments of the invention, the transmitted signal is optionally modified by some or all of the transceivers nodes as it is relayed from one transceiver node to another, so the signal received by a transceiver node is not the same as the signal it transmits.

For example, some or all of the transceiver nodes can receive the signal from adjacent transceiver nodes and transmit a slightly modified signal incorporating additional data collected at that transceiver node. Typically, this additional data would report on local conditions (e.g. pressure, temperature, salinity, pH, gas concentration, vibration, etc.) at the transceiver node and would also be coded to identify the transceiver node generating the additional data. In this way, the signal can be interpreted at the surface to identify local environmental conditions at each separate transceiver node that recorded a modified signal, so that local conditions can be measured along the length of the string and not just at the end of the string where traditionally all of the sensors are located.

Once each of the transceiver nodes are made up on the string of elongate members and run into the well, their relative positions in the string are fixed, and this allows the physical origin of the data within the well bore to be tied to the identification (ID) code of the signal. The length of each elongate member and the ID code for the transceiver node on it are recorded, either manually or electronically, as the assembly is run in to the well. These positional data are then correlated with the signal IDs being received at surface to identify the physical location of each data transmitted.

Embodiments of the invention permit reconfiguration of the data transmission pathway either by relocation of transceiver nodes or through self-adaptive changes or manual intervention to the transmissions, to optimise the system performance. For example, if one transceiver node fails, or if one conductor on one tubular fails, the system can be reconfigured or replaced during a full or partial routine recovery of the bottom hole assembly to surface (a ‘trip’) or between trips, to optimise performance.

Typically the signal generator can be a conventional downhole sensor already incorporated in the string. The Bottom Hole Assembly of a typical drilling system (BHA) is typically provided with suitable sensors, sometimes known as Measurement While Drilling tools, Logging While Drilling Tools, Seismic While Drilling tools, and Formation Evaluation While Drilling tools, and in certain embodiments of the invention, the apparatus transmits measurement data generated from one or more of the BHA sensors.

In other embodiments of the invention the signal comprises data from a sensor incorporated in the string, optionally incorporated in a signal transceiver node. In certain embodiments, the signal generator can comprise a conventional third party signal generator that can be incorporated within a tool in the string (e.g. in the BHA) or can be out with the string, elsewhere in the well. At surface, a dedicated transceiver node, typically not on the string, can typically pick up the signal from the transceiver node on the tubular closest to surface and relay it to a computer or data collection station containing software to decode, segregate, and display the various data variables that have been carried up the string.

In addition to relaying data from various sections of the well to surface, data can be sent from surface to node locations in the string as commands to control devices in the string. These commands could be to switch off or on specific sensors, change sample rates or resolution of sensors, and also, commands to initiate change of state in mechanical, hydraulic, or electrical tools within the string. These commands from surface can also be used to control the data transmission characteristics of the system such as data rate and data frequency.

The tubular can typically comprise a drilling tubular such as drill pipe, and the string of tubulars can typically have a drill bit, and optionally a bottom hole assembly at the lower end. In this specification, the upper end of the drill string can typically be considered to be the end nearest the wellhead at the surface, and the lower end of the drill string can typically be considered to be the end furthest from the wellhead and closest to the location where the bit is cutting into the rock formation. Usually the lower end is physically lower than the upper end, but in horizontal drilling this is not necessarily the case, and references to upper and lower ends should be construed accordingly.

In one embodiment the apparatus can incorporate an energy generator to deliver energy to the transceiver nodes, typically formed as part of the transceiver node. In certain embodiments with energy generators, a portion of the transceiver sleeve is free to rotate about the pipe while the remainder is rigidly clamped to the pipe. As the pipe is rotated as in the normal process of drilling, the rotating portion of the sleeve remains stationary relative to the well bore due to friction of contact while the remainder of the clamp rotates with the pipe to which it is attached.

In such embodiments, a energy generator can be incorporated in the transceiver converting the kinetic energy generated by the relative rotation of the two sections of the transceiver collar or tubular into electrical energy to power the transceiver in a similar manner to a dynamo or alternator, the stator of the generator device being imbedded in the rotating sleeve, and rotor in the portion that is rigidly clamped to the pipe or into the pipe surface itself, or vice versa. To provide continuous power during non-rotational periods of operation, the electrical energy generated as a result of the normal drill string rotation in the wellbore is typically used to maintain the charge of rechargeable battery cells within the transceiver.

In another embodiment the generator can comprise solid-state electro mechanical or magneto-mechanical materials or devices, such as a piezoelectric material that generates electrical energy in response to tension, compression or vibration, or a magnetostrictive material that generates energy in response to mechanical loads. In such embodiments the device will be secured within the transceiver node unit such that the mechanical loading experienced by the transceiver unit during normal well operations transfers the tension, or compression, or vibration required by these devices to produce an electrical energy into the generator component. To provide continuous power during non-rotational periods of operation, the electrical energy generated maintains the charge of rechargeable battery cells within the transceiver.

Optionally the transceiver nodes can have mechanical functions such as tubular centralisers or friction-reduction stabilisers. Existing components of the string can optionally be modified to be part of the data transmission pathway.

Potentially many different specifications of tubular can be converted by applying the signal conductors and transceiver nodes as retrospective modifications. Tubulars according to the invention that may conventionally have a protective coating to the internal diameter can typically be recoated and repaired without detriment to the data transmission effectiveness.

Drill pipe mechanical connections at the end termini of the tubulars are typically not part of the data network, and so can be designed according to the requirements of the physical connection, meeting torque limits and other parameters without affecting data transmission. Damaged thread on used tubulars can be repaired by re-cutting, reforming, or replacing end connectors without compromising data transmission. In applications to oil and gas wells, following the drilling process, operations to conduct reservoir fluids to surface, or pressure support fluids from surface to reservoir will typically continue through the life of the well. For these operations the drilling tubulars are typically replaced with thinner walled, larger internal diameter tubulars usually referred to as tubing, production tubing or casing. Embodiments of the invention described previously for drilling applications can be incorporated into these post-drilling application embodiments in exactly the same way for the purposes of data and command transmission.

Optionally the signal conductor is located on the outer surface of the tubular and/or on the inner surface of the tubular and/or embedded within the wall of the tubular. The electrical conductor is typically fully embedded in the coating or between the abrasion resistant and coating layers, and is typically sandwiched between them, in order to insulate it from the tubular and from the environment outside (or inside) the tubular.

The transceiver nodes can optionally incorporate electronic control circuitry that controls adaptive mesh network features used to improve system redundancy. Embodiments of the invention allow better access to detailed real-time downhole data without recovering (‘tripping’) the BHA back to surface, which can improve safety, increase rate of penetration (ROP), extend life of the BHA by better forecasting of local conditions liable to damage the bit and drill string, and can also improve positional accuracy through the reservoir, reducing the need to drill beyond target. The various aspects of the present invention can be practiced alone or in combination with one or more of the other aspects, as will be appreciated by those skilled in the relevant arts. The various aspects of the invention can optionally be provided in combination with one or more of the optional features of the other aspects of the invention.

Also, optional features described in relation to one embodiment can typically be combined alone or together with other features in different embodiments of the invention. Various embodiments and aspects of the invention will now be described in detail with reference to the accompanying figures. Still other aspects, features, and advantages of the present invention are readily apparent from the entire description thereof, including the figures, which illustrates a number of exemplary embodiments and aspects and implementations. The invention is also capable of other and different embodiments and aspects, and its several details can be modified in various respects, all without departing from the spirit and scope of the present invention.

Accordingly, the drawings and descriptions are to be regarded as illustrative in nature, and not as restrictive. Furthermore, the terminology and phraseology used herein is solely used for descriptive purposes and should not be construed as limiting in scope. Language such as “including”, “comprising”, “having”, “containing” or “involving”, and variations thereof, is intended to be broad and encompass the subject matter listed thereafter, equivalents, and additional subject matter not recited, and is not intended to exclude other additives, components, integers or steps. Likewise, the term “comprising” is considered synonymous with the terms “including” or “containing” for applicable legal purposes.

Any discussion of documents, acts, materials, devices, articles and the like is included in the specification solely for the purpose of providing a context for the present invention. It is not suggested or represented that any or all of these matters formed part of the prior art base or were common general knowledge in the field relevant to the present invention.

In this disclosure, whenever a composition, an element or a group of elements is preceded with the transitional phrase “comprising”, it is understood that we also contemplate the same composition, element or group of elements with transitional phrases “consisting essentially of”, “consisting”, “selected from the group of consisting of”, “including”, or “is” preceding the recitation of the composition, element or group of elements and vice versa.

DESCRIPTION OF DRAWINGS

All numerical values in this disclosure are understood as being modified by “about”. All singular forms of elements, or any other components described herein are understood to include plural forms thereof and vice versa. In the accompanying drawings;

FIG. 1 is a schematic perspective view of a first and second tubular forming a string of tubulars incorporating apparatus according to the invention;

FIG. 2 is a schematic view of a drill string (not to scale) incorporating the tubulars shown in FIG. 1;

FIG. 3 is a perspective cut away view showing the internal detail of the separate layers of the tubular shown in FIG. 1;

FIG. 4a is a perspective cut away view showing the detail of the layers from another perspective;

FIG. 4b is a perspective cut away view showing the detail of the layers of an alternative signal conductor configuration;

FIG. 4c is a perspective cut away view showing the detail of the layers of a further alternative signal and conductor configuration;

FIG. 5 is a perspective sectional view of a coating layer incorporating a signal conductor suitable for use in the tubular of FIG. 1.

FIG. 6a is a schematic perspective of a Transceiver node housing.

FIG. 6b is a schematic perspective of the Transceiver outline and location with respect to the Transceiver node and an adjacent electrical conductor.

Referring now to the drawings, a typical onshore or offshore oil or gas well as shown in FIG. 2 utilises a drilling apparatus P located above a well head H through which a drill string S is rotated from the surface apparatus P. At the downhole end of the string S, a drill bit B on a bottom hole assembly (BHA) cuts a hole into the formation, thereby forming the borehole of the well. The string S is made up of sections of tubular drill pipe that are connected end to end by box and pin connections which can be conventional in the art.

As shown in FIG. 1, each section of tubular T1, T2, etc. in the string S typically has an enlarged diameter section at the end housing an internal connection (e.g. a box and pin thread connection at respective ends). Between the enlarged diameter sections, the nominal outer diameter of the tubular T1, T2, etc. is typically less than the outer diameter of the end terminal connector sections. In accordance with the invention, the reduced diameter central sections between the enlarged diameter end terminal sections of the tubular T1, T2 are covered at various locations around the circumference by a signal conductor, that typically extends along the length of the reduced diameter portion of the tubular T1, and optionally, but not typically extends onto the enlarged diameter end terminal sections, and typically terminates some way short of each end of the tubular T1, T2, etc.

The optional signal conductor in the present embodiment typically comprises a multi-layer component that is wrapped or otherwise applied to the outer surface of the narrower central section of the tubular T1. As best described with reference to FIGS. 3, 4 a, 4 b and 4 c, the narrow central section 12 of the tubular T1 typically comprises a steel tube having a typical diameter of 4 to 7 inches, although the invention can typically be applied to many different specifications of tubular. The outer surface of the central section 12 typically has an insulating coating layer applied to it, typically by flame-spray coating techniques, for example by HVOF coating (high velocity oxy-fuel coating) or plasma spraying directly on to the outer diameter of the pipe.

These techniques involve spraying the components in fluid form from guns and nozzles that force the components forming the coating at high velocities and temperatures through the nozzle of the gun and onto the surface of the pipe to be coated, resulting in a very high adherence of the materials to the substrate of the pipe. Typically, the deposited material forms a state when first deposited which yields electrical and mechanical properties which are different from the normal bulk material properties. For materials such as copper and other metals and for non-metallics such as polymers or ceramics, this creates electrical properties that can be altered by various degrees of compositional and topological changes in the sprayed materials and by processes such as thermal annealing post-deposition.

Typically, the coating can be sprayed circumferentially around the entire outer surface of the central section 12 or in discrete axial strips. In other embodiments, the coating layer can be formed separately as a planar flexible sheet and wrapped around the outer surface of the central section 12, being fixed in place by adhesive or bonding by other means.

On the outer surface of the insulating coating layer, a signal conductor 8 is applied. The signal conductor 8 is typically in the form of metallic strips, or alternatively metallic sheet or mesh, as shown in this embodiment. In the present embodiment, the mesh 8 is formed as a cylindrical shape and comprises a network of individual strands formed by weaving or braiding individual strands of copper wire or thin copper sheet together to form numerous inter-connections between adjacent strands. In the present embodiment, approximately 40 to 60 strands of copper wire or copper strips are woven in a regular pattern so that each copper strip extends helically around the outer circumference of the applied coating layer. In the present embodiment, approximately half of the copper wires or strips extend in a clockwise helix, and the others extend in an anti-clockwise helix.

Typically, the pitch of the strands in each helix is approximately similar, so that all strands extending in a clockwise helix are parallel, as are those which extend in an anti-clockwise helix. Typically, the anti-clockwise and clockwise helices are set at the same pitch, although in opposite directions, so that the number of interconnections made by each wire remains at approximately the same intensity as the woven signal conductor 8 extends axially along the tubular T1. Typically, the inner coating layer, applied to the outer surface of the tubular, electrically insulates and physically isolates the outer surface of the tubular 12 from the signal conductor 8, so that none of the metallic strands or wires forming the signal conductor 8 come into physical contact with the outer surface of the tubular T1 at any point. Typically, the inner coating layer 10 extends axially along the tubular T1 beyond the signal conductor 8, in order to isolate the signal conductor 8 from the outer surface of the tubular T1.

On the outer surface of the metallic strand 8, the tubular T1 typically has a further, optionally outer-most, layer 4, which is typically formed of a hardwearing material that primarilyinsulates and isolates the signal conductor 8 from the external environment surrounding the tubular T1. Typically, the outer layer 4 also extends axially beyond the signal conductor 8, to isolate the signal conductor from the external environment. The outer layer 4 typically comprises a hardened material that is typically resistant to abrasion damage by wearing or scoring of the material.

Typically, the layer of outer material 4 can be relatively thick or robust in comparison to the signal conductor 8 to provide a tough durable outer layer to protect the signal conducting layer against impact, wear and erosion. The outer layer can comprise for example, alumina or alumina compounds, with interspersed polymer or resin materials, and/or other hard materials that are wear resistant. Typically, the outer layer 4 also incorporates an electrical resistance in order to resist the passage of the electrical signal radially through the outer layer 4. Optionally, a further layer of additional wear-resistant materials such as Tungsten Carbide may be applied to the outer surface of the whole, to provide further mechanical robustness, These outer materials may optionally have electrically-insulating properties or electrically conducting properties for improved electrical signal transmission and electrical shielding.

In typical embodiments, the inner layer can primarily function as an electrical insulator, and ceramic materials such as Alumina, Zirconia, Silica or similar materials, optionally with interspersed polymer or resin materials can be used in the formation of the inner layer. Other suitable materials for the inner layer may include polymers or epoxies or other electrical insulators or non-conductors.

FIG. 4b shows an alternative similar configuration using axially aligned metal strips 14 as a signal conductor in place of the previous mesh configuration.

In certain embodiments, for example, that shown in FIG. 5, the signal conductor can be enclosed within a discrete layer that is typically formed separately as a planar sheet and applied as one wrapped layer on to the outer surface of the tubular, or formed as a cylinder and offered to the tubular T1. FIG. 5 shows an exemplary signal conductor that is enclosed between two flexible planar sheets of plastics material before being wrapped around the coating layer 10. In certain embodiments, the inner coating layer 10 is unnecessary, typically in those embodiments that have the encapsulated signal conductor shown in FIG. 5. Optionally, the encapsulated signal conductor can have a hardened or otherwise abrasion resistant outer surface coating, which may render unnecessary the separate outer coating 4 shown in FIGS. 3 and 4. Optionally both may be implemented together.

Referring once again to FIG. 1, each tubular T1, T2, etc. typically has respective transceiver nodes C1, C2, etc. The transceiver node C1 typically picks up signals transmitted from the sensors associated with the bottom hole assembly and drill bit B. The signals transmitted by the bottom hole assembly and drill bit B are typically emitted in radio frequency form, which are picked up by the signal conductor 8 in tubular T1, and received by transceiver node C1 at the top end of tubular T1. The transceiver node C1 then relays the signal from tubular T1 to tubular T2, where it is typically picked up by the signal conductor 8 on tubular T2, and relayed to transceiver node C2, although in embodiments without signal conductors the signal is relayed direct from one transceiver node C1 to the next transceiver node C2 (or C3) on the string, which can be on an adjacent length of tubular T2 or another non-adjacent length of tubular T3.

The transceiver nodes can optionally be in direct contact with the signal conductor 8 in each of the tubulars T, but this is not necessary, and typically the transceiver nodes C1, C2, etc. can wirelessly pick up and optionally amplify the transmitted signals passing along the signal conductor 8 without having a direct physical or electrical connection to the signal conductor 8.

In certain embodiments, the transceiver nodes C1, C2 can be located radially outwardly from the signal conductor 8. In use, the transceiver nodes C1, C2 relay the signal from the drill bit to the surface platform P, where it can be interpreted to gather more information about the wellbore conditions at the drill bit B.

Typically, each tubular T1, T2 etc has respective transceiver nodes C1, C2, etc., but this is not necessary, and transceiver nodes C can optionally be placed on every second, third, fourth, fifth, or sixth tubular T, depending on desired signal strength and power of transceivers. Optionally each tubular may have placed on it more than one transceiver node.

Typically, each transceiver node C1, C2 etc. is substantially identical and can optionally relay the same signal that it receives, but in certain embodiments of the invention, each transceiver node C1, C2 etc. has a unique identifying electronic code which is encoded by electronic components in the transceiver node into the received code, and which is integrated into the code that is transmitted. In addition, transceiver nodes C1, C2 etc. can optionally incorporate sensors that monitor local conditions at the position of the transceivers, and can also encode this in the signal that is transmitted from each respective transceiver node along with the unique identification code of that transceiver node, In one embodiment of a transceiver node shown in FIG. 6 a the transceiver node can incorporate a collar extending around the circumference of the tubular T.

The collar can have a component fixed to the tubular F, but can optionally incorporate an additional sleeve section S which is free to rotate around the axis of the tubular. The rotor and stator elements of a dynamo generator can be incorporated into the transceiver node assembly with one being imbedded in the clamped section F and the other in the rotating sleeve S. As the tubular is rotated as part of normal drilling operations, the clamped section will turn with the tubular and the sleeve section will remain rotationally static relative to the wellbore. The relative rotation of the rotor and stator form an energy generator to power the transceiver, and typically converts the kinetic energy generated by the relative rotation of the transceiver node sleeve and the tubular into electrical or potential energy to power the transceiver. This electrical energy generated as a result of the normal drill string rotation in the wellbore is typically used to maintain the charge of rechargeable battery cells within the transceiver node.

In another embodiment the generator can comprise solid-state electromechanical or magneto-mechanical materials or devices, such as a piezo electric material that generates electrical energy in response to tension, compression or vibration, or a magnetostrictive material that generates energy in response to mechanical loads. In such embodiments the device will be secured within the transceiver unit such that the mechanical loading experienced by the transceiver unit during normal well operations transfers the tension, or compression, or vibration required by these devices to produce an electrical current into the generator component. The piezoelectric generator requires no moving parts, and can be incorporated entirely within either a rigidly clamped section of the transceiver node housing, or alternatively within the rotating sleeve component if present. To provide continuous power during non-rotational periods of operation, the electrical energy generated maintains the charge of rechargeable battery cells within the transceiver.

In one embodiment of the transceiver node shown schematically in FIG. 6b , a RF transceiver Tn detail is shown in close proximity to an adjacent electrical conductor E each housed on the same elongate member. In this embodiment, to optimise the effectiveness of the RF transmissions with the allowable radial clearances of the transceiver node housing, the RF transceiver is shown laid onto the circumference of the tubular. In this embodiment there exists no direct electrical connection between the transceiver node and the electrical conductor. 

We claim:
 1. Apparatus for downhole transmission and reception of data in an oil or gas well comprising a plurality of transceiver nodes located along a string in a wellbore, the string being made up of sections of tubular pipe having no coating for the purposes of signal transmission, and the data being wirelessly transmitted as a radiofrequency (RF) signal in an adaptive mesh network so that in the event of a node failure, the transmitting node changes the transmitted signal to by-pass the silent node and reach the next node in sequence to provide system redundancy.
 2. Apparatus according to claim 1 wherein commands are wirelessly transmitted with the data to control or operate downhole tools or devices.
 3. Apparatus according to claim 1 wherein the transmitting node changes the transmitted signal by amplitude to transmit over a greater distance to bypass the silent node.
 4. Apparatus according to claim 1 wherein the transmitting node changes the transmitted signal by frequency to transmit over a greater distance to bypass the silent node.
 5. Apparatus according to claim 1 wherein the transmitting node maintains as default the new communication pathway and signal transmission characteristics.
 6. Apparatus according to claim 1 wherein the data is transmitted bi-directionally along the tubular pipes.
 7. Apparatus according to claim 1 wherein the data is transmitted at a transmission rate greater than a Megabit per second.
 8. Apparatus according to claim 1 wherein one or more transceiver nodes incorporates one or more sensors allow data to be gathered from multiple points along the tubular pipes.
 9. Apparatus according to claim 1 wherein the transceiver nodes comprise collars that are applied to the outer surface of the tubular pipes.
 10. Apparatus according to claim 1 wherein the transceiver nodes are incorporated in a sub-assembly terminating in similar connections to the tubular pipes and inserted between two such pipes.
 11. Apparatus according to claim 1 wherein the transceiver nodes are located in a side-pocket mandrel within the wall of the tubular pipe. 